Effect of capillary number on the residual oil saturation during chemical flooding

The paper presents experimental results of studying capillary displacement curves in chemical methods of enhancing oil recovery. The analysis of the theory of capillary number and changes in this parameter in chemical methods of enhancing oil recovery is carried out. The results of studies of capillary displacement curves are analyzed, and general patterns and features of the behavior of these curves in various experimental conditions are revealed. The analysis showed that with a change in formation wettability, porosity, permeability, and pore structure, the capillary displacement curves change. Under changing formation conditions, classical capillary displacement curves previously obtained in the course of basic experiments do not allow predicting residual oil saturation, and in addition, the maximum oil recovery does not correspond to the maximum values of capillary numbers. In the practice of oil field development, there is no need to use high concentrations of surfactants to reduce the surface tension to an ultra-low level. Addition of polymer, and alkali (in appropriate concentration) provides high oil recovery due to interaction of surfactants, polymer and alkali. Currently, in China, ASP flooding technology (alkaline-surfactant-polymer flooding – alkaline flooding and combined use of alkali, surfactant, and polymer) is the most effective method of enhancing oil recovery in flooded oil fields and gives good results. Therefore, it is necessary to study the micromechanisms of residual oil mobility and filtration. Studies of the capillary displacement curve, considering the structure of the reservoir and its basic filtration characteristics, are of decisive importance in the development of oil fields in China, and these curves can also be used in world practice as a basis for enhancing oil recovery.

1. An Y, Yao X, Zhong J, Pang S, Xie H. (2022). Enhancement of oil recovery by surfactant-polymer synergy flooding: A review. Polymers and Polymer Composites, 30. DOI: 10.1177/09673911221145834

2. Chatzis I., Morrow N.R. (1984). Correlation of Capillary Number Relationships for Sandstone. Society of Petroleum Engineers Journal, 24(05), pp. 555–562. DOI: 10.2118/10114-pa

3. Chatzis I., Kuntamukkula M.S., and N.R. Morrow (1988). Effect of Capillary Number on the Microstructure of Residual Oil in Strongly Water-Wet Sandstones. SPE Res Eng, 3, pp. 902–912. https://doi.org/10.2118/13213-PA

4. Deng Chao, Hou Baofeng, Yang Xiwu, etc. (2022). The Mechanism of Surfactants Changing Reservoir Wettability and Enhancing Recovery. Contemporary Chemical Industry, 51(04), pp. 757–761+765. (In Chinese) DOI: 10.13840/j.cnki.cn21-1457/tq.2022.04.025

5. Foster W.R. (1973). A Low-Tension Waterflooding Process. J Pet Technol, 25, pp. 205–210. https://doi.org/10.2118/3803-PA

6. Gong L., Liao G., Luan H., Chen Q., Nie X., Liu D., & Feng Y. (2020). Oil solubilization in sodium dodecylbenzenesulfonate micelles: New insights into surfactant enhanced oil recovery. Journal of Colloid and Interface Science, 569, pp. 219–228. doi: 10.1016/j.jcis.2020.02.083

7. Guo, H., Song, K., & Hilfer, R. (2022). A brief review of capillary number and its use in capillary desaturation curves. Transport in Porous Media, 144(1), pp. 3–31. https://doi.org/10.1007/s11242-021-01743-7

8. Jiang Haifeng (2004). Experimental research on the influence of capillary number on the displacement effect of ASP flooding under different conditions. Daqing Petroleum Institute. (In Chinese)

9. Li Kanyun, Li Cuiping, Zhao Guang et al. (2014). Experiment on reasonable capillary number for binary compound flooding in heterogeneous reservoir. PGRE, 21(1), pp. 87–91. (In Chinese) DOI: 10.13673/j.cnki.cn37-1359/te.2014.01.022

10. Li Mingyan, Lu Xiangguo, Sun Gang et al. (2012). Study on Viscosity and Interfacial Tension of Compound Surfactant Ternary Compound System. Oilfield Chemistry, 29(03), pp. 326–330. (In Chinese) DOI: 10.19346/j.cnki.1000-4092.2012.03.017

11. Melekhin S.V., Mikhailov N.N. (2015). Experimental study of residual oil mobilization during waterflooding of carbonate reservoirs. Neftyanoe khozyaystvo, 8, pp. 72–76. (In Russ.)

12. Mikhailov N.N. (1985). On the methodology for assessing oil recovery by influencing the bottomhole zone and the reservoir as a whole. Coll. papers: Geological and geophysical studies with physicochemical and thermal methods of enhancing oil recovery. Tr.MING, vol. 191. (In Russ.)

13. Mikhailov N.N. (1992). Residual oil saturation of developed formations. Moscow: Nedra, 240 p. (In Russ.)

14. Mikhailov N.N. (2011). Petrophysical support for new technologies for additional recovery of residual oil from technogenically altered deposits. Karotazhnik, 7(205), pp. 126–137. (In Russ.)

15. Mikhailov N.N., Vysokovskaya E.S. (1982). Forecasting Residual Oil Saturation Based on a Study of the Dynamics of Clay Mud Filtrate Penetration into the Reservoir. Coll. papers: Improving Field Study Methods to Enhance Oil Recovery. Moscow: Nedra, pp. 85–101. (In Russ.)

16. Mikhailov N.N., Glazova V.I., Vysokovskaya E.S. (1983). Forecasting Residual Oil Saturation in Designing Reservoir and Borehole Zone Stimulation Methods. Scientific and Technical Review. Moscow: VNIIOENG, ser.: Neftepromyslovoe delo, vol. 22(71), 71 p. (In Russ.)

17. Mikhailov N.N., Melekhin S.V. (2021). The coefficient of oil displacement by water at variable values of capillary number. Neftyanoe khozyaystvo, 4, pp. 62–66. (In Russ.) DOI: 10.24887/0028-2448-2021-4-62-66

18. Mo J., Mikhailov N.N., Wang H. (2024). Influence of Reservoir Microstructure on the State of Residual Oil According to Nuclear Magnetic Resonance (NMR) Spectroscopy. Georesursy = Georesources, 26(1), pp. 100–108. https://doi.org/10.18599/grs.2024.1.8

19. Rücker, M., Bartels, W. B., Garfi, G., Shams, M., Bultreys, T., Boone, M., ... & Luckham, P. F. (2020). Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale. Journal of colloid and interface science, 562, pp. 159–169. https://doi.org/10.1016/j.jcis.2019.11.086

20. Shakhverdiev A.Kh. (2014). Once again about oil recovery. Neftyanoe khozyaystvo, 1, pp. 44–48. (In Russ.)

21. Shakhverdiev A.Kh., Mandrik I.E. (2007). The influence of technological features of hard-to-recover hydrocarbon reserves production on the oil recovery factor. Neftyanoe khozyaystvo, 6, pp. 76–79. (In Russ.)

22. Tehrani-Bagha A.R., Singh R.G., & Holmberg K. (2012). Solubilization of two organic dyes by cationic ester-containing gemini surfactants. Journal of Colloid and Interface Science, 376(1), pp. 112–118. DOI: 10.1016/j.jcis.2012.02.016

23. Wu Wenxiang, Wang Demin (2011). Research on polymer viscoelasticity to improve oil displacement efficiency. Journal of China University of Petroleum (Natural Science Edition), 35(05), pp. 134–138. (In Chinese)

24. Zhan F., Gong L., Luan H., Chen Q., Liao G., & Feng Y. (2021). Enhancing Oil Recovery by Low Concentration of Alkylaryl Sulfonate Surfactant without Ultralow Interfacial Tension. Journal of Surfactants and Detergents, 24(4), pp. 669–681. DOI: 10.1002/jsde.12488